Enhanced oil displacement in a reservoir is highly affected by wettability alterations in conjunction with the lowering of viscosities during steam assisted gravity drainage (SAGD) for bitumen extraction. The impartation of energy in the form of heat to the fluid by injecting steam triggers an alteration to a more water-wet state during SAGD. However, the presence of three distinct phases in the reservoir has implications for the effective modeling of the complex fluid dynamics. Dependency of the relative permeability endpoints on the temperature realized as a function of the introduction of steam is difficult to model. Optimization of any steam process requires simulation in order to adequately characterize years of flow and so a model that is capable of representing three phase flow is necessary. To obtain this a pseudo-two phase relative permeability is proposed that assumes fractional flow theory is valid and treats the experiments as a waterflood.
In this study, experimental recovery data for two SAGD experiments and one hot water flood are empirically matched by manipulating relative permeabilities. The analytical approach implemented allows for the representation of fluid flow in the reservoir by achieving a pseudo-two phase relative permeability that results in comparable performance to the experiments. Waterflooding techniques were utilized which allowed for the negation of the steam phase in the model and so two-phase flow was established.
The sensitivity of the relative permeability curves to temperature change results in the inability to formulate a generic three-phase curve and so the pseudo-two phase curve is valuable for the purpose of simulation. The methodology presented enables the formulation of a simplified relative permeability that is unique to each process used and in that specific location. The model that was established was validated and proven credible by the good match with the experimentally obtained values.
Luo, Haishan (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number.
The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy oil reservoirs, and hence can facilitate the optimization of heavy-oil EOR projects.
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
Dwarakanath, Varadarajan (Chevron) | Dean, Robert M. (Chevron) | Slaughter, Will (Chevron) | Alexis, Dennis (Chevron) | Espinosa, David (Chevron) | Kim, Do Hoon (Chevron) | Lee, Vincent (Chevron) | Malik, Taimur (Chevron) | Winslow, Greg (Chevron) | Jackson, Adam C. (Chevron) | Thach, Sophany (Chevron)
Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
Achieving maximum oil recovery utilizing CO2 has limitations when operating at, or very close, to the Minimum Miscibility Pressure (MMP) of the CO2 in the oil. A modular source of CO2 would allow Enhanced Oil Recovery (EOR) flooding of "stranded" and shallow reservoirs. Unfortunately, modular sources of CO2 production often include CO and N2 mixed with the CO2. Thus, testing for EOR application of a mixed gas-containing CO2, N2, and CO was initiated.
Bench scale testing using Rising Bubble Apparatus (RBA), Slim Tubes, and linear core flood have been conducted on oils ranging from 16-42° gravities having viscosities of 0.5-280 cp. All tests were conducted at reservoir temperatures and pressures. CO, being a strong reducing agent, was further tested on reservoir rock containing swelling clays with hydrated ferric hydroxides. Due to the apparent reduction of the ferric hydroxide, and the liberation of its water of hydration, an increase in matrix permeability and clay stabilization, was observed.
For most oils tested, the CO2/CO mixture increased rate of oil recovery by 2-3X, using only 50-60% as much gas/bo as compared to pure CO2. Recovery factors of 80%, at immiscible pressures 30-40% below CO2 MMP, were achieved. Addition of 15% N2 (v/v) to the CO2/CO mixture did not impair oil recovery. Interfacial testing (IFT) of oils, using pure CO, demonstrated a lowering of the IFT. RBA testing of asphaltine-rich heavy oils has shown that a mixture of CO2/CO dissolves into the oil at a far faster rate than either CO2 or CO individually and faster than the sum of both individual gases. A similar test using non-asphaltine type oils did not display this unique characteristic. Slim tube testing suggests that CO facilitates the mobilization of asphaltine-rich heavy oils and lowers viscosity. A linear corefloods of a reservoir containing 5% smectite + illite/smectite + and chlorite demonstrated a 275% increase in matrix permeability. Packed column tests, containing quartz sand and bentonite, demonstrated up to 300-900% increase in permeability in the presence of CO.
Thus a method to recover oil faster, from stranded reservoirs, at pressures below MMP, using significantly less gas, appears possible. In addition the use of CO, either alone or in combination with CO2 and/or N2, has been shown to increase matrix permeability. Such a gas mixture may be beneficial to achieving low pressure EOR from shallow, "stranded" reservoirs, non-conventional shale oil reservoirs, and viscous, heavy oil reservoirs at low temperatures. Incorporation of CO, or CO2/CO, in a frac fluid, or alternately as a post frac cleanup for shale oil and gas applications appears to warrant investigation.
Waterflood implementation accounts for more than half of the oil production worldwide. Despite the observations and extensive research from a large number of floods and thousands of simulation studies, managing waterfloods and Enhanced Oil Recovery (EOR) floods is still a technical challenge. A major contributor to this challenge are waterflood induced fractures (WIF). Managing waterfloods is a multivariable problem although WIF are one aspect, it is by no means the only controlling factor.
The best evidence that WIF are one of the main factors controlling flow in reservoirs is the insensitivity of injection pressure to injection rates. With our experience, in hundreds of waterfloods, we have frequently observed this phenomenon in the field data. If fluid flow depended on diffusive Darcy flow alone, we would expect higher injection rates with higher injection pressures. However, it is common to observed relatively constant injection pressures over a wide range of water injection rates. Rapid well communication and changes in water cuts that vary with injection rates also support an interpretation of high permeability induced fractures between injector and producer. In some reservoirs, interwell tracer data can be used to determine the influence of induced fracture features. The interwell tracers usually show very fast water movement.
Induced fractures in waterfloods and EOR projects can be caused by a number of mechanisms such as but not limited to, pressure depletion, changing pressure regimes, thermal effects, or plugging effects. These fractures can either be beneficial to the reservoir performance or effect performance negatively. Benefits include improved injectivity and increased throughput of the displacing fluid. Negative effects can come in the form of reduced volumetric sweep efficiency, impaired ultimate recovery or injected fluid losses out of zone.
Case studies, theory, and available literature from Western Canada will be reviewed in order to suggest and improve reservoir management strategies for waterfloods. We have completed hundreds of waterflood feasibility, waterflood management and EOR flood studies worldwide and continue to be amazed and humbled by the complexity that many waterfloods and EOR floods exhibit due to induced fracturing. WIF and EOR induced fractures (EIF) are common and should be analysed to optimize production. Growth of the WIF, response to waterflood with the presence of WIF, implication of WIF and reservoir management are the main areas which will be addressed.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.
Li, Yuxiang (The University of Texas at Austin) | Lu, Jun (The University of Texas at Austin) | Churchwell, Lauren (The University of Texas at Austin) | Tagavifar, Mohsen (The University of Texas at Austin) | Weerasooriya, Upali (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Primary and secondary oil recovery from naturally fractured carbonate reservoirs with an oil-wet matrix is very low. Enhanced oil recovery from these reservoirs using surfactants to alter the wettability and reduce the interfacial tension have been extensively studied for many years, but there are still many questions about the process mechanisms, surfactant selection and testing, experimental design and most importantly how to scale up the lab results to the field. We have conducted a series of imbibition experiments using cores with different vertical and horizontal dimensions to better understand how to scale up the process. There was a particular need to perform experiments with larger horizontal dimensions since almost all previous experiments have been done in cores with a small diameter, typically 3.8 cm. We adapted and modified the experimental method used for traditional static imbibition experiments by flushing out fluids surrounding the cores periodically to better estimate the oil recovery, including the significant amount of oil produced as an emulsion. We used microemulsion phase behavior tests to develop high performance surfactant formulations for the oils used in this study. These surfactants gave ultra-low IFT at optimum salinity and good aqueous stability. Although we used ultra-low IFT formulations for most of the experiments, we also performed tests at higher IFT for comparison. Even for the higher IFT experiments, the capillary pressure is very small compared to gravity and viscous pressure gradients. We also developed a simple analytical model to predict the oil recovery as a function of vertical and horizontal fracture spacing, rock properties and fluid properties. The model and experimental data are in good agreement considering the many simplifications made to derive the model. The scaling implied by the model is significantly different than traditional scaling groups in the literature.
During an Alkaline-Surfactant-Polymer (
In this study, steady-state (
For brine/oil systems some dependence of apparent viscosity on rock permeability was observed; for systems with surfactants no such trend was noticable. The addition of surfactants substantially reduced the apparent viscosities; the viscosity reducing impact of surfactants could be balanced by the addition of polymer. Fractional flow analysis showed that the addition of surfactants reduces the impact of capillary forces resulting in straightened relative permeability curves and higher aqueous phase relative permeability end points.
It is anticipated that this study leads to a fast and fit for purpose characterization method of
Hou, Binchi (Research Institute of Shaanxi Yanchang Petroleum (Group) CO., LTD.) | Liu, Hongliang (China Petroleum Logging TuHa Business Division) | Bian, Huiyuan (Xi'an University of Science and Technology) | Wang, Chengrong (China Petroleum Logging TuHa Business Division) | Xie, Ronghua (Daqing Oilfield CO.LTD., PetroChina) | Li, Kewen (China University of Geosciences(Beijing)/Stanford University)
Capillary pressure and resistivity in porous rocks are both functions of wetting phase saturation. Theoretically, there should be a relationship between the two parameters. However, few studies have been made regarding this issue. Capillary pressure may be neglected in high permeability reservoirs but not in low permeability reservoirs. It is more difficult to measure capillary pressure than resistivity. It would be useful to infer capillary pressure from resistivity well logging data if a reliable relationship between capillary pressure and resistivity can be found. To confirm the previous study of a power law correlation between capillary pressure and resistivity index and develop a mathematical model with a better accuracy, a series of experiments for simultaneously measuring gas-water capillary pressure and resistivity data at a room temperature in 16 core samples from 2 wells in an oil reservoir were conducted. The permeability of the core samples ranged from 9 to 974 md. The gas-water capillary pressure data were measured with confining pressures using a semi-porous plate technique. We developed the specific experimental apparatus to measure gas-water capillary pressure and resistivity simultaneously. The results demonstrated that the previous power law model correlating capillary pressure and resistivity works well in many cases studied. A more general relationship between the exponent of the power law model and the rock permeability was developed and verified using the experimental data.